The latitude/longitude mapping system is widely used worldwide, except in the United States. This approach is more orderly and easily allows the wells to be located in relation to other known wells or landmarks. The "lat/long" system is now being introduced in the United States in conjunction with the township/range scheme. Selecting offset wells to be used in data collection is important. Using Figure 1 as an example, assume that a 13,000-ft prospect is to be drilled in the northeast corner of Section 30, T18S, R15E. The best candidates for offset analyses are shown in Table 1. Although these wells were selected for control analysis, available data from any well in the area should be analyzed.
Juan A. Pinzon, SPE, joined BHP Billiton (BHPB) as drilling development manager of its Global Petroleum Division. Pinzon has more than 20 years' oil and gas industry experience and has held engineering and management positions at BP, Schlumberger, and Occidental Petroleum (OXY). He began his career with BP where he gained experience in exploration, development, and appraisal projects in Colombia, South America. He worked with Schlumberger as drilling engineering manager for North and South America for its Drilling and Measurement Division, based in Houston. Pinzon also worked for BP America, where he held drilling positions in projects in southeast Texas, south Louisiana, and Wyoming.
Epoxy-based resins have recently been used within the industry as a substitute for conventional cements, primarily because of their enhanced ductility, increased compressive strength, and ability to avoid contamination. As operators seek new products that can withstand higher differential pressures and help to ensure well integrity throughout production life, the use of resins is an important alternative for providing effective zonal isolation.
Nevertheless, the identification of resin bond and placement behind pipe remains challenging with current cement evaluation technology. The increased elasticity inherent in resins attenuates acoustic waves and impedes expected wave propagation. Ultrasonic tools can identify the presence of resins when casing coupling exists, but are unable to determine annular volume or formation bond.
A resin evaluation method has been recently established that is based on trend analysis of various data sets acquired through logging intervention. The unique properties of epoxy-based resins are the focus of this analysis, which involves using a multivariable data comparison for identification purposes when resins are used as a discrete phase in a multiple cement system.
This technique was recently applied to logging data from one south Louisiana well to determine the location of a resin batch that was part of a multistage cementing operation of 9-5/8 in. production casing. An 11.5-lbm/gal resin lead was set during the first cementing stage, immediately below a second-stage 16.4-lbm/gal cement tail.
The operator desired confirmation that the resin had been set at the estimated proposed depth, in accordance with the cementing program.
Salehi, S. (University of Louisiana - Lafayette) | Aladsani, A. (Kuwait Oil Company) | Shahri, M.P. (University of Tulsa) | Karimi, M. (Weatherford) | Ezeakacha, C. (University of Louisiana at Lafayette)
Casing while Drilling (CwD) is an efficient method by which to increase the fracture gradient in narrow pore-fracture pressure sedimentary basins and deep offshore applications. It offers hydraulic improvements and the ability to plaster cuttings to the wellbore wall, which can enhance the wellbore's hoop stress by wedging the created fractures. Although successful field applications of increasing wellbore integrity have been reported, uncertainties remain regarding the mechanisms and how to operationally capture the maximum attainable wellbore pressure. These uncertainties include the hydraulic complexities of fluids, role of Particle Size Distribution (PSD) and how it relates to the plastering effect, type of drilling fluids, borehole shape, role of lost circulation materials (LCM), and casing eccentricity.
This paper presents numerical, analytical and experimental methods to study the contributing factors in CwD applications.
Laboratory experiments were conducted to evaluate the Particle Size Distribution (PSD) and filtration rate of the mud mixed with cuttings from a recently drilled well. Several tests were conducted using Permeable Plug Testing (PPT) equipment to evaluate the role of different LCMs, to fill the PSD gap and to capture the strengthening effect.
In addition, advance finite-element methods were used to model the near wellbore area and hoop stress changes with consideration of the formation's poro-elastic properties. Furthermore, the frictional pressure lost during the CwD operation was evaluated using Computational Fluid Dynamics. Analytical models were used to investigate different boundary conditions when applying finite-element analysis.
The numerical simulations and laboratory experiments in this work were based on a recently drilled well in South Louisiana, where severely depleted sections were drilled successfully. Previous drilling records in this area report multiple problems with lost circulation, tight holes and other wellbore stability issues. Results from the numerical models and laboratory experiments agree well with field observations. The analysis presented in this paper indicates that an optimum PSD can significantly mitigate lost circulation and minimize the need to add LCM.
This paper revisits advancements in drilling high-temperature and high-pressure wells during the period 1950-1980. It was during this period that many of the planning and drilling techniques in use today were first identified, and in many cases, resolved on the drilling rig. The paper is drawn from personal recollections and published material, with particular emphasis on contributions from operator and service-company personnel at the rig site in the Gulf of Mexico and Gulf Coast basin. 1950 was a time when well kicks were "controlled?? on a local basis with whatever seemed to work, generally the constant annulus pressure or constant pit volume methods. Many of the well flows, fortunately, were saturated salt water and less hazardous than gas. Fracture gradient was an unknown value and stuck pipe and lost circulation seemingly occurred by happenstance. Mud solidification was similarly dealt with on a local basis with dilution of incorporated native solids and/or the addition of more dispersant in water-based muds. This also reinforced the importance of the high lime mud's ability to tolerate contamination.
The paper serves to highlight how resourceful field personnel working in concert with innovative staff engineers can achieve extraordinary success. This was and is especially critical in an industry fraught with uncertainty.
In 1950, the drilling industry had little idea of how to predict geopressures, a term coined by Charles Stuart,48, and even less of an idea of how to deal with High-Temperature, High-Pressure (HTHP) wells. The initial development of technology adequate to economically drill HTHP wells was piecemeal and by trial and error. Theory often followed practice. During the period 1950-1980, while there were some very notable exceptions, more typical deep well temperatures started to approach 300 °F and pressures approached 15,000 psi.
Geological papers published from the 1920's to the 1960's discussed earth temperatures and pressures from an academic viewpoint, 1,10,32,47,48,49 , but their value was not fully recognized until they were compiled with developing drilling technology in the late 1970's.
Higher temperatures and higher pressures required better drilling fluids leading to a progression from phosphate muds to high-lime, low-lime, gypsum, and lignosulfonate drilling fluids with 10% diesel oil that were more resistant to the conditions in the HTHP wells. At the same time, "true?? oil-based drilling fluids gave way to invert emulsions that ultimately resolved many of the problems with wellbore stability.
A landmark paper on well control methods by Obrien and Goins 38 opened the door to more discussion about predicting wellbore pressures instead of just reacting to them. The key thoughts about pressure caps and transition zones led to major breakthroughs in pressure prediction.
Mobile computing devices did not exist then, but special slide rules and nomographs were developed by different service companies to allow application of some of these techniques at the wellsite. By 1980, most of the new geopressured operating techniques were accepted as basic standards for HTHP drilling, and industry was starting incorporate predictive and operating procedures into computers that were becoming commonplace and readily available.
Atlantis is a giant oil field with challenges that require a multi-disciplinary and phased approach to reservoir development. Initial development focused on the better-imaged extra-salt segment of the structure after eight appraisal penetrations revealed over a 1,500 ft oil column contained in several high quality thick pay sands. Signals of the reservoir complexity that would be associated with Atlantis were seen from the beginning. The early wells found variable fluid contacts, fluid compositional variations, large previously undetected faults, and what turned out to be perched water. Development drilling continued while the facilities were being fabricated. The drilling results strengthened confidence that there were large in-place resources but heightened concerns about complexity. In response, the development plan was modified to include ocean-bottom-seismic, downhole-flow-control completions, and a second production drill center. Initial reservoir performance revealed sub-seismic baffles that resulted in lower stabilized well productivity and more complex compartmentalization than expected. Integrated analyses of static and dynamic data enabled the integrated team to demonstrate that recovery per well was similar to pre-drill expectation and modification to the development plan would allow sustained production growth. Challenges going forward include appraisal and development of remaining segments of the field to effectively grow production and extend production plateau, and efficient operation of the wells, subsea architecture and production facilities.
The reuse of existing well bores is a cost-saving technique used by oil and gas producers in mature fields. This process usually requires the removal of tubing and packers to allow the well to be deepened or sidetracked. The tubing removal process is often made difficult when the tubing is stuck inside the casing because of mechanical binding or binding caused by dehydrated mud or sand in the annulus between the tubing and casing. Conventional direct and indirect methods of finding the stuck point(s) along an interval of tubing, such as free-point indicator tools or acoustic attenuation measurements, have proved themselves useful in finding the point(s) where the tubing is stuck. However, when the sticking is caused by uncompacted sand that has entered the annular space between the tubing and casing, these conventional stuck-pipe indication methods are often inconclusive or misleading.
Technological advancements in the design and development of slim, 1 11;'16-in. outside diameter (OD), radial cement bond tools allow the application of a new measurement to find sand-stuck tubing intervals. These tools provide up to six independent, closely spaced acoustic attenuation measurements distributed radially around the tool body. When the recording operation is performed inside the tubing, the increased sensitivity of these tools to sound attenuation, as compared with conventional omnidirectional amplitude signals, allows sand intervals along the outside of the tubing to be distinguished from intervals where little or no sand is present. This information is used to select the best depth to sever or back-off the free tubing in order to reduce the interval length and expense associated with the washover process required to remove the remaining tubing from the wellbore.
An overview of conventional stuck-pipe recovery techniques is provided here, along with a brief explanation of applicable acoustic technology. A case study of a South Louisiana well is presented to demonstrate the application and illustrate the cost savings which can be gained by use of this very new technology.
Oil and gas producers operating in maturing fields such as the U.S. Gulf of Mexico basin continually strive to reduce the expense of drilling new wells. The presence of oyster leases and dredging restrictions in inland bay fields severely limits, and in some cases prohibits, the drilling of new wells. One method of overcoming these obstacles includes reentering existing wells to take advantage of the casing string already cemented in place. This process usually requires the removal of old tubing and packer assemblies that were once used to produce hydrocarbons from now-depleted zones. Their removal clears the way for recompleting to shallower zones, deepening the well, or sidetracking to reach new reservoirs.
The recovery of stuck tubing has plagued the oil and gas industry since its inception and is commonly necessary in remedial well operations (Bernat 2001). Conditions that can cause tubing to get stuck are often mechanical in nature, including collapsed or parted casing, dehydrated drilling mud, and formation sand filling the annular space between the tubing and casing.
The most common methods of recovering stuck tubing include impact tools (jars), washover operations, low-frequency vibrators, and milling tools (Stoesz and DeGeare 2000). These recovery techniques have been used in the industry for many years with varying degrees of success, depending upon the amount of time spent on the process. Because jarring, washover, and milling techniques require a drilling or workover rig to be moved to the wellsite, the amount of time spent on the pipe recovery process is kept to a minimum so as to avoid a negative impact on project economics.
Risk factors such as the type of sticking, hole angle, well depth, and material to be removed should be evaluated to determine the best method of pipe recovery (Stoesz and DeGeare 2000). The usual process for removing mud-stuck or sand-stuck tubing is to reciprocate the tubing with the rig to free up a length of tubing, and then to perform an electric line backoff to allow recovery of the free section. Wash pipe is used to circulate and remove dehydrated mud or sand by washing over the remaining tubing string, and then the free-point, backoff, and recovery process is repeated (Walker 1984). When the tubing cannot be freed by jarring and reciprocating, the challenge is to determine the proper depth interval for washing over the tubing in order to minimize rig time and other associated costs.
The reuse of existing well bores is one cost saving technique employed by oil and gas producers in mature fields. This process usually requires the removal of tubing and packers to allow the well to be deepened or side-tracked. The tubing removal process is often made difficult due to its being stuck inside casing due to mechanical binding, or binding caused by dehydrated mud or sand in the annulus between the tubing and casing. Conventional direct and indirect methods of finding the stuck point(s) along an interval of tubing, such as Free Point Indicator Tools or Acoustic Attenuation measurements, have proven themselves useful in finding the point(s) where the tubing is stuck. However, when the sticking is due to uncompacted sand that has entered the annular space between the tubing and casing, these conventional stuck pipe indication methods are often inconclusive.
Technological advancements in the design and development of slim, 1-11/16 in. OD, radial cement bond tools allow the application of a new measurement to find sand-stuck tubing intervals. These tools provide up to six independent, short-spaced, acoustic attenuation measurements distributed radially around the tool body. When recorded inside tubing, their increased sensitivity to sound attenuation, as compared to conventional omni-directional amplitude signals, allows sand intervals along the outside of the tubing to be distinguished from intervals where little or no sand is present. This information is used to select the best depth to sever or back-off the free tubing in order to reduce the interval length and expense associated with the washover process required to remove the remaining tubing from the wellbore.
An overview of conventional stuck pipe recovery techniques is discussed along with a brief explanation of applied acoustic technology. A case example of a South Louisiana well is presented to demonstrate the application and illustrate the cost savings gained by use of this newest technology.